Highlights from the November FERC Open Meeting

December 9th, 2015 by Miles Farmer, Legal Fellow, Energy & Transportation Program

Promoting Competitive Provision of Primary Frequency Response Service (RM15-2). In February 2015, FERC issued a notice of proposed rulemaking (NOPR) to allow sellers with market-based rate authority for energy and capacity sales to also sell primary frequency response service at market-based rates. Frequency response service, according to FERC, is “a resource standing by to provide autonomous, pre-programmed changes in output to rapidly arrest large changes in frequency until dispatched resources can take over.” We filed comments supporting this proposal, noting that FERC’s market-based approach would encourage cost-effective provision of this necessary service. At its November meeting, FERC issued a final rule, Order No. 819, that in accordance with our recommendations, substantially adopted the proposal as set forth in the NOPR. The rule adopts the same market power screens for sales of primary frequency response service as are currently used for energy and capacity sales.

As we explained in our comments, Order No. 819 will help energy storage, responsive demand, and other clean technologies enter into the market for providing frequency response service by allowing voluntary purchases of these services to meet the needs of balancing authorities. This rule promotes competition to meet the increased demand for frequency regulation services stemming from the new Frequency Response and Frequency Bias Setting Reliability Standard, which was approved by FERC in January 2014.

 

FERC Orders Grid Operators to Provide Information Regarding Price Formation in Energy and Ancillary Services Markets (AD14-14). FERC issued an order directing regional grid operators to submit reports addressing five issues regarding price formation in their energy and ancillary services markets. Each grid operator’s report must cover (1) how market rules compensate fast-start resources (certain natural gas resources and diesel generators that ramp up quickly); (2) how commitment and dispatch decisions are made to address multiple contingencies (the loss of multiple generators at the same time); (3) how the grid operator employs “look-ahead modeling,” which refers to tools that assess near-term unit commitment and dispatch decisions; (4) how uplift payments are allocated (uplift payments are payments made to resources that are dispatched in a manner resulting in a shortfall between the resource’s offer costs and the revenue the resource earned through market clearing prices); and (5) how the grid operator provides for transparency in the process by which prices are developed. FERC’s call for data is another step on its recent and sensible effort to address price formation issues, and will help ensure that FERC has adequate information before it takes further action.

 

FERC Proposes to Repeal the Exemption to Reactive Power Requirements for Wind Generators (RM16-1). FERC issued a notice of proposed rulemaking (NOPR) to eliminate the exemption for wind generators from the requirement to provide dynamic reactive power. Reactive power is needed to control transmission line voltage and thereby ensure efficient and reliable operation of the system. Generators that deliver “dynamic” reactive power are able to absorb reactive power with greater speed and continuity than those that deliver “static” reactive power. Currently, small wind generators are entirely exempted from the requirement to provide dynamic reactive power, and large wind generators need only provide dynamic reactive power if the transmission provider shows that reactive power capability is needed to ensure safety or reliability. These exemptions reflect the recognition that, unlike traditional synchronous generators, wind generators need to install special equipment in order to maintain reactive power capability. In its NOPR, FERC argues that these exemptions should be eliminated because this special equipment has become more commercially available and less costly, and because continued use of the exemption could cause reliability problems as the penetration of wind resources increases. Subject to comment, FERC’s NOPR preliminarily concludes that the continued exemption from the reactive power requirement is now unjust and unreasonable. In principle, we support FERC’s initiative to remove the reactive power exemption for wind generators, so long as the compensation and terms for such reactive power supply are reasonable. FERC’s action will create a uniform rule for such power supply by wind generators, which could be preferable to region-by-region regulation on this issue. Comments on this NOPR are due on January 26, 2016.

 

FERC Approves New Reliability Standards Proposed by NERC (RM15-7; RM15-16). FERC issued two new final rules, Order Nos. 817 and 818, approving new reliability standards put forth by the North American Electric Reliability Corporation (NERC).  These rules help to clarify the divisions of responsibilities between reliability coordinators and transmission operators, and refine and consolidate different planning and operations standards into more streamlined rules. By doing so they eliminate gaps and ambiguities in the prior standards, and should help enhance the reliability of the system.

 

FERC Conditionally Accepts MISO’s Proposed Resource Adequacy Rule Revisions (ER11-4081-001; ER11-4081-002). In June, 2012, FERC issued an order regarding MISO’s resource adequacy provisions that, among other things, (i) rejected MISO’s proposal for a mandatory capacity auction, (ii) required MISO to justify its proposed capacity zone boundaries, (iii) directed MISO to explain what historical data it would provide regarding coincident peak demand forecasts on which it bases its planning reserve requirements, and (iv) accepted MISO’s proposal to include energy efficiency resources as planning resources in its resource capacity construct.

At its November meeting, FERC issued two orders pertaining to this proceeding. First, it denied requests for rehearing of the June 2012 order. It reasoned that a mandatory capacity market is inappropriate for the MISO region, which is composed primarily of vertically-integrated utilities.

Second, FERC approved the compliance filing that MISO submitted in response to the June 2012 order. In lieu of its mandatory capacity market requirement, MISO proposed to amend its Tariff to provide that it will assess a Capacity Deficiency Charge of 2.748 times the Cost of New Entry on Load Serving Entities (LSEs) that fail to demonstrate that they have sufficient capacity resources to meet their Planning Reserve Margin requirements. FERC accepted MISO’s proposed charge, and disagreed with objections by the Illinois Commerce Commission that this charge is too high. FERC also accepted a proposed capacity zone boundaries map filed by MISO, reasoning that MISO adequately explained that the zones borders reflect major transmission constraints in the region while respecting Local Balancing Authority and state borders to the extent possible. In addition, FERC accepted MISO’s proposed data disclosures regarding its demand forecasts. MISO’s proposal makes its historical data regarding peak demand available to market participants upon request, and provides that this data shall include the dates and times of summer peak demands for the MISO region beginning with the year 2005. MISO also promises to make peak demand forecast data for future summers publicly available on its website by the end of each calendar year.

 

FERC Denies Our Request to Direct PJM to Update Its Load Forecast Values for Purposes of Its Capacity Auctions Conducted in 2015 to PJM’s New Load Forecasting Model and Thereby Prevent Over-procurement of Resources and Overcharging of Consumers (EL15-83). On June 30, 2015, we joined with a coalition of consumer protection groups and environmental advocates in filing a complaint requesting FERC to direct PJM to update its load forecast values beginning with its capacity auctions conducted in 2015. In the alternative, we argued that FERC should require PJM to reinstate a “holdback” provision that it had included for previous capacity auctions, but that it eliminated beginning with the capacity auctions conducted in 2015.

Prior to its 2015 capacity auctions, PJM was close to finalizing its new load forecast model that is more accurate than its previous load forecast methodology. Despite this, PJM declined to use its enhanced load forecast model for its 2015 capacity auctions. Had PJM used its new methodology for purposes of those auctions, its load forecasts would have been reduced by roughly 7,000 MWs or more, and consumers could have saved more than $600 million. FERC rejected our request to direct PJM to use its updated methodology for capacity auctions conducted in 2015. FERC concluded that we failed to demonstrate that the now-outdated methodology used by PJM for the 2015 capacity auctions produced unjust and unreasonable results, despite PJM’s public acknowledgement that its new methodology is superior and despite the fact that using the old methodology costs consumers millions of dollars. FERC stated that PJM demonstrated that its revised forecasting methodology was not yet complete, and concluded that as a result there is no basis for requiring the new methodology’s use until it has been finalized.

In addition, FERC rejected our alternative request to direct PJM to reinstate its “holdback” provision. While it was originally promulgated for a different purpose, the holdback provision helped to mitigate PJM’s persistent over-forecasting of load by setting aside a certain percentage of the load requirement from earlier auctions for satisfaction through later auctions, if such procurement ultimately proved to be necessary. In rejecting our request to reinstate the holdback, FERC referred to its previous approval of PJM’s decision to eliminate the holdback, in which FERC stated, despite PJM’s history of consistently over-forecasting load, that it was not persuaded that a holdback requirement is necessary to address load forecast errors.

While our complaint always faced long-odds due to the fact that PJM had not yet finalized its enhanced methodology, FERC’s approval of PJM’s use of its old methodology effectively ensures that customers will be overcharged by approving the procurement of more capacity through PJM’s 2015 auctions than is necessary to ensure the reliability of the system. As PJM refines its new methodology, we will continue to fight to ensure that it adequately accounts for all energy efficiency and demand response resources.

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